Forming Multiple Deviated Wellbores

ABSTRACT

A system includes a primary wellbore and a plurality of secondary wellbores. The primary wellbore includes a substantially vertical portion extending from a terranean surface to a predetermined location above a first target subterranean formation; a curved portion coupled to the substantially vertical portion and extending through the first target subterranean formation above a second target subterranean formation containing at least one of oil or gas; and a substantially horizontal portion coupled to the curved portion and extending through the first target subterranean formation and adjacent the second target subterranean formation. The plurality of secondary wellbores are coupled to the primary wellbore and extend angularly downward into the second target subterranean formation.

TECHNICAL BACKGROUND

This disclosure relates to systems and methods for forming wellboreswithin a subterranean formation and, more particularly, to systems andmethods for forming wellbores within one or more subterranean formationsutilizing one or more deviated wellbore portions extending from anadjacent geological formation to a hydrocarbon bearing formation.

BACKGROUND

Over the last century, oil and gas has been produced fromhydrocarbon-bearing geologic strata (“productive formation”) within theEarth's crust by drilling vertical wellbores, which penetrate thesepotentially productive layers. In most cases, the productive formationsare horizontally-planed layers of solid sedimentary rock generally foundat depths from approximately 2,000 feet to 20,000 feet below thesurface. These productive formations usually range from 10 to 200 feetin thickness. Thus, it may be typical for a vertically-drilled oil orgas well to have less than one percent of its total wellbore lengthactually exposed to and in contact with targeted productive formations.Moreover, it may be unusual for any more than ten percent of a verticalwellbore to be exposed to a productive formation.

In recent years, technology, equipment, and processes have beendeveloped which allow oil and gas producers to engage in a process knownas “horizontal drilling.” In the horizontal drilling process, drillersmay first drill vertically into the Earth to a specified point above atargeted productive formation and then bend, or “deviate,” the wellborein a controlled manner over a distance of several hundred feet toachieve a horizontal wellbore through the target productive formation.This horizontal drilling process has improved over the years. With thesehorizontal drilling techniques, wells may now be drilled that containhorizontal wellbores through and exposed to tens, hundreds, and eventhousands of feet of the targeted horizontally-planed formation, ratherthan the typical 10 to 200 feet of exposure achieved with verticaldrilling methods. Indeed, horizontal wells may have over fifty percentof their total wellbore length within and exposed to the targetedproductive formation.

The basic physics underlying oil and gas production involves a migrationof hydrocarbons through permeable rock formations to areas of lowerpressure created by a wellbore. These hydrocarbons may then flow throughthe wellbore's steel piping system known as “casing” and are eventuallybrought to the surface. Because horizontal wellbores drilled throughtargeted formations are exposed to more of the targeted formation andmay have a much greater proportional exposure to the productive rock,these wells may produce at much higher rates and drain the productiveformations much more effectively as compared to vertically drilledwells.

Modern drilling techniques for both vertical and horizontal wells mayutilize rotary drilling methods that circulate a fluid, such as, forexample, compressed air, foam, a liquid such as water, and/or a liquidwith one or more chemical additives (also known as “drilling mud”),through the wellbore as the well is drilled. The compressed aircirculating method may generally be more efficient and environmentallyfriendly than drilling on mud. However, a number of productiveformations that may be drilled vertically using the air circulationprocess may not be easily and/or efficiently drilled horizontally usingthe air circulation process. The geologic characteristics of theseformations and the altered flow dynamics of circulation mediums involvedin drilling horizontal wellbores may make horizontal drilling throughthese formations difficult and expensive. Horizontal wellbores throughthese formations may thus be difficult to drill even using the lessefficient fluid “drilling mud” method.

Various natural gas producing regions of the United States, for example,may contain productive formations with great productive potential butwhich are composed of a highly organic shale rock that may be unsuitablefor horizontal drilling using compressed air circulation drillingprocesses. In some cases, however, a rock layer directly above oradjacent to the productive formation may be a lesser organic, morebrittle, competent rock formation (e.g., shale) that may be well-suitedfor horizontal drilling using compressed air (or foam) drillingprocesses.

Furthermore, after completion of the drilling process, certain naturalgas wells producing from horizontal shale formations may be stimulatedprior to or during the production phase by the use of a hydro-fracturingprocess. This hydro-fracturing process, often known as “Tracing,”involves the injection of a mixture of proppant (most often sand) andwater along with other chemical compounds into the formation, thuscreating man-made fractures and increasing the permeability within therock that allows the natural gas held in the formation to migrate morereadily toward the wellbore and eventually be produced at the surfacethrough the wellbore's casing.

During such fracing processes, the amount of fresh water needed to fraca drilled well, such as a horizontally-drilled shale well, may besubstantial. For example, a typical hydro-frac process on a horizontalwell requires as much as 1,000,000 gallons of water. Some largerhorizontal well frac jobs may require as much as 4,000,000 gallons ofwater. Thus, the use of water in fracing horizontal wells has beenperceived as a threat to the fresh water balance of nature in certainriver basins. The cost to the well owner to assemble this amount offresh water at the well site can be very high; in some cases exceedingseveral hundred thousand dollars. Most of the fresh water that isinjected into the well during the fracing process flows back out of thewell as “frac water” and returns to the surface after the fracingprocess is completed. The frac water that returns to the surface maylikely contain varied amounts of substances, such as chemicals andcompounds used in the fracing process and dissolved solids fromnaturally occurring substances within the productive formations. Thesesubstances can include: certain metal and mineral elements, variouschloride compounds, and naturally occurring chemicals, such as bariumsulfate. The existence of the now-contaminated water at the surfacepresents additional economic and regulatory issues. Using currentprocesses and technology, disposal of this frac water can costsubstantial sums per well, to say nothing of regulatory concernsgenerated by the storage, handling, and disposal of the frac water.

SUMMARY

In one general embodiment, a method includes forming a first wellboreportion from a terranean surface to a predetermined depth in or near afirst target subterranean formation, where the first wellbore portionhas an upper section extending from the terranean surface downward in asubstantially vertical manner for at least a portion of the depth to thefirst targeted subterranean formation. The method includes forming asecond wellbore portion coupled to the first wellbore portion, where thesecond wellbore portion is formed substantially horizontal to and insubstantial entirety within the first target subterranean formation. Themethod further includes forming a plurality of third wellbore portionsincluding a plurality of deviated wellbores extending angularly downwardinto a lower second target subterranean formation from the secondwellbore portion, where the second target subterranean formationincludes at least one of oil or gas.

In some specific embodiments, the first wellbore portion may be aslanted wellbore from the terranean surface to the predetermined depth.Further, forming the upper vertical section of the first wellboreportion may include drilling through one or more a geologic formationsutilizing air as a drilling fluid. Forming the second wellbore portionmay include drilling through the first target subterranean formationutilizing air as a drilling fluid. Forming the plurality of thirdwellbore portions may include drilling through the second targetsubterranean formation utilizing air as a drilling fluid. Forming theupper vertical section of the first wellbore portion may includedrilling through one or more a geologic formations utilizing foam as adrilling fluid. Forming the second wellbore portion may include drillingthrough the first target subterranean formation utilizing foam as adrilling fluid. Forming the plurality of third wellbore portions mayinclude drilling through the second target subterranean formationutilizing foam as a drilling fluid.

In certain specific embodiments, the first target subterranean formationmay be directly adjacent the second target subterranean formation andbetween the terranean surface and the second target subterraneanformation. In addition, the plurality of deviated wellbores may beformed from the second wellbore portion at a downward angle less than 90degrees from horizontal. Forming a plurality of third wellbore portionsincluding a plurality of deviated wellbores extending angularly into asecond target subterranean formation from the second wellbore portionmay include forming a plurality of deviated wellbores extendingangularly into the second target subterranean formation from the secondwellbore portion and completely through the second target subterraneanformation. Forming a plurality of third wellbore portions including aplurality of deviated wellbores extending angularly into a second targetsubterranean formation from the second wellbore portion may include:forming a first group of deviated wellbores extending angularly into thesecond target subterranean formation; and forming a second group ofdeviated wellbores extending angularly into the second targetsubterranean formation, where the second group of deviated wellbores maybe separated from the first group of deviated wellbores by a lateraloffset.

The method may further include determining the lateral offset betweenthe first and second groups of deviated wellbores based at least in parton a predetermined fracture process or a predetermined stimulationprocess for the second target subterranean formation. In addition,forming a first group of deviated wellbores extending angularly into thesecond target subterranean formation may include forming a first groupof deviated wellbores extending angularly into the second targetsubterranean formation at a first angle from horizontal. Forming asecond group of deviated wellbores extending angularly into the secondtarget subterranean formation may include forming a second group ofdeviated wellbores extending angularly into the second targetsubterranean formation at a second angle distinct from the first angle.In some embodiments, the method may further include determining thefirst and second angles based at least in part on a predeterminedfracture process or a predetermined stimulation process for the secondtarget subterranean formation.

In some embodiments, the plurality of deviated wellbores may include afirst plurality of deviated wellbores and the method may furtherinclude: forming a fourth wellbore portion coupled to the first wellboreportion, where the fourth wellbore portion may be radially offset fromthe second wellbore portion and formed substantially horizontal to andin substantial entirety within the first target subterranean formation;and forming a second plurality of deviated wellbores extending angularlyinto the second target subterranean formation from the fourth wellboreportion. In specific embodiments, the second target subterraneanformation may include a hydrocarbon bearing shale formation.Additionally, at least one of the first wellbore portion, the secondwellbore portion, and the plurality of deviated wellbores may be formedby rotary drilling equipment. Forming a plurality of deviated wellboresextending angularly into a second target subterranean formation from thesecond wellbore portion may include forming a plurality of deviatedwellbores extending downwardly into a second target subterraneanformation from the second wellbore portion and angularly offset fromhorizontal and vertical.

In another general implementation, a system includes a primary wellboreand a plurality of secondary wellbores. The primary wellbore includes asubstantially vertical portion extending from a terranean surface to apredetermined location above a first target subterranean formation; acurved portion coupled to the substantially vertical portion andextending through the first target subterranean formation above a secondtarget subterranean formation containing at least one of oil or gas; anda substantially horizontal portion coupled to the curved portion andextending through the first target subterranean formation and adjacentthe second target subterranean formation. The plurality of secondarywellbores are coupled to the primary wellbore and extend angularlydownward into the second target subterranean formation.

In some specific embodiments of the system, the substantially verticalportion of the primary wellbore may be formed by drilling through one ormore a geologic formations utilizing air as a drilling fluid. Further,the substantially horizontal portion of the primary wellbore may beformed by drilling through one or more a geologic formations utilizingair as a drilling fluid. At least one of the plurality of secondarywellbores may be formed by drilling through one or more a geologicformations utilizing air as a drilling fluid. The substantially verticalportion of the primary wellbore may be formed by drilling through one ormore a geologic formations utilizing foam as a drilling fluid. Thesubstantially horizontal portion of the primary wellbore may be formedby drilling through one or more a geologic formations utilizing foam asa drilling fluid. At least one of the plurality of secondary wellboresmay be formed by drilling through one or more a geologic formationsutilizing foam as a drilling fluid.

In some embodiments, the first target subterranean formation may bedirectly adjacent the second target subterranean formation and betweenthe terranean surface and the second target subterranean formation. Inaddition, the plurality of secondary wellbores may be coupled to thesubstantially horizontal portion of the primary wellbore. The pluralityof secondary wellbores may be formed from the substantially horizontalportion at a downward angle less than 90 degrees from horizontal. Atleast one of the plurality of secondary wellbores may extend completelythrough the second target subterranean formation.

In certain embodiments, the plurality of secondary wellbores may includea first group of secondary wellbores extending angularly downward intothe second target subterranean formation; and a second group ofsecondary wellbores extending angularly downward into the second targetsubterranean formation, where the second group of secondary wellboresmay be separated from the first group of secondary wellbores within thesecond target subterranean formation by a lateral offset. The lateraloffset between the first and second groups of secondary wellbores may bebased at least in part on a predetermined fracture process or apredetermined stimulation process of the second target subterraneanformation. The first group of secondary wellbores may extend angularlydownward into the second target subterranean formation at a first anglefrom horizontal and the second group of secondary wellbores may extendangularly downward into the second target subterranean formation at asecond angle from horizontal, where the second angle is distinct fromthe first angle. In some aspects, the first and second angles may bedetermined based at least in part on a predetermined fracture process ora predetermined stimulation process of the second target subterraneanformation.

In some embodiments, the curved portion may be a first curved portionand the system may further include a second curved portion coupled tothe substantially vertical portion and radially offset from the firstcurved portion around the substantially vertical portion, where thesecond curved portion extends through the first target subterraneanformation above the second target subterranean formation. The system mayfurther include a second substantially horizontal portion coupled to thesecond curved portion and extending through the first targetsubterranean formation and adjacent the second target subterraneanformation. The system may further include a second plurality ofsecondary wellbores extending angularly downward into the second targetsubterranean formation from the second substantially horizontal portion.The second target subterranean formation may include a hydrocarbonbearing shale formation. At least one of the primary wellbore and theplurality of secondary wellbores may be formed by rotary drillingequipment.

Various embodiments of a multiple deviated wellbore system according tothe present disclosure may include one or more of the followingfeatures. For example, the deviated wellbore system may include one ormore horizontally-drilled wellbores drilled through one or moreformations located above a targeted productive formation and a number ofsharp-dipping wellbores into or through a productive formation. As usedherein, “formation” may include one or more portions, or the entirety,of a body, or strata, of rock. The result may allow for easier, moreefficient, and economical penetration into the target productiveformation, greater efficiency in drilling the target productiveformation and easier communication of fractures through and, in somecases, rubbilization of the formation. The deviated wellbore system mayalso allow for horizontal, or directional, drilling in competentformations (e.g., shale) above a highly organic targeted productiveformation. The deviated wellbore system may also include drillingmultiple wellbores, or paths, for fracturing, draining, and/or producinginto and/or from the productive formation from a long radiushorizontal-style wellbore to the productive formation. Thus, thedeviated wellbore system may allow an entire drilling process to beconducted using an efficient and environmentally friendly compressed airor foam drilling process for both the horizontal wellbore section andthe multiple drainage paths. The deviated wellbore system may result inan economic and environmentally efficient drilling process forhorizontal wells that are developed to produce hydrocarbons (e.g., oiland/or gas).

Various embodiments of a multiple deviated wellbore system according tothe present disclosure may include one or more of the followingfeatures. For example, the deviated wellbore system may allow forsavings of millions of gallons of water during a traditional hydraulicfracing process by enabling the use of inert gases or high quality foam,thus eliminating the potential to contaminate the ground water and othersub-surface strata with the foreign hydraulic frac materials. Further,when water is used for a frac process, the deviated wellbore system mayallow for the well system to be stimulated using very little water. Forinstance, the multiple drainage paths may be formed at specificintervals and spacings in order to minimize water requirements. In somecases, the deviated wellbore system may require as little as one percentof the water typically used to frac horizontal shale wells.Additionally, the deviated wellbore system may more quickly andefficiently produce hydrocarbons from a geological formation by, forexample, encouraging more efficient rubbilization of the formationbetween two or more of the drainage paths.

These general and specific aspects may be implemented using a device,system or method, or any combinations of devices, systems, or methods.The details of one or more implementations are set forth in theaccompanying drawings and the description below. Other features,objects, and advantages will be apparent from the description anddrawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a side cross-sectional view of a first verticalportion of one embodiment of a deviated wellbore system according to thepresent disclosure;

FIG. 2 illustrates another side cross-sectional view of a second portionof one embodiment of a deviated wellbore system according to the presentdisclosure;

FIG. 3 illustrates another side cross-sectional view of a third portionof one embodiment of a deviated wellbore system including a deviatedwellbore according to the present disclosure;

FIG. 4 illustrates another side cross-sectional view of a third portionof one embodiment of a deviated wellbore system including a deviatedwellbore group according to the present disclosure;

FIGS. 5A-B illustrate additional cross-sectional views of one embodimentof a deviated wellbore system including multiple deviated wellboregroups according to the present disclosure;

FIG. 6 illustrates a side cross-sectional view of one embodiment of adeviated wellbore system including multiple deviated wellbore groupsduring a fracing, stimulation, or production operations according to thepresent disclosure; and

FIG. 7 illustrates a plan view of one embodiment of a system includingmultiple deviated wellbore systems according to the present disclosure.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

In some embodiments, a deviated wellbore system according to the presentdisclosure includes an articulated wellbore drilled from the surface toa target geological formation located above the target productiveformation. The articulated wellbore may include a substantially verticalportion, a radiused portion, and a substantially horizontal portionlanding in the target geological formation to be drilled horizontally.In some embodiments, the target geological formation is located adjacenta production formation containing one or more hydrocarbons, such as oilor gas. In some embodiments, the production formation may be a formationcontaining natural gas such as a shale formation, siltstone, sandstonematrix or limestone matrix. The deviated wellbore system may alsoinclude one or more deviated wellbores, or completion paths (e.g.,production, fracture, stimulation paths), drilled from the substantiallyhorizontal portion of the wellbore into the productive formation.Completion operations may be conducted through the deviated wellbores tomore efficiently produce the hydrocarbons.

FIG. 1 illustrates a portion of one embodiment of a deviated wellboresystem 10 according to the present disclosure. Generally, each deviatedwellbore system 10 accesses one or more subterranean formations, andprovides easier and more efficient production of any hydrocarbonslocated in such subterranean formations. Further, the deviated wellboresystem 10 may allow for easier and more efficient fracing or stimulationoperations. As illustrated in FIG. 1, the deviated wellbore system 10includes a drilling assembly 15 deployed on a terranean surface 12. Thedrilling assembly 15 may be used to form a vertical wellbore portion 20extending from the terranean surface 12 and through one or moregeological formations in the Earth. One or more subterranean formations,such as productive formation 55, are located under the terranean surface12. As will be explained in more detail below, one or more wellborecasings, such as a surface casing 30 and intermediate casing 35, may beinstalled in at least a portion of the vertical wellbore portion 20.

In some embodiments, the drilling assembly 15 may be deployed on a bodyof water rather than the terranean surface 12. For instance, in someembodiments, the terranean surface 12 may be an ocean, gulf, sea, or anyother body of water under which hydrocarbon-bearing formations may befound. In short, reference to the terranean surface 12 includes bothland and water surfaces and contemplates forming and/or developing oneor more deviated wellbore systems 10 from either or both locations.

Generally, the drilling assembly 15 may be any appropriate assembly ordrilling rig used to form wellbores or boreholes in the Earth. Thedrilling assembly 15 may use traditional techniques to form suchwellbores, such as the vertical wellbore portion 20, or may usenontraditional or novel techniques. In some embodiments, the drillingassembly 15 may use rotary drilling equipment to form such wellbores.Rotary drilling equipment is known and may consist of a drill string 17and a bottom hole assembly 45. In some embodiments, the drillingassembly 15 may consist of a rotary drilling rig. Rotating equipment onsuch a rotary drilling rig may consist of components that serve torotate a drill bit, which in turn forms a wellbore, such as the verticalwellbore portion 20, deeper and deeper into the ground. Rotatingequipment consists of a number of components (not all shown here), whichcontribute to transferring power from a prime mover to the drill bititself. The prime mover supplies power to a rotary table, or top directdrive system, which in turn supplies rotational power to the drillstring 17. The drill string 17 is typically attached to the drill bitwithin the bottom hole assembly 45. A swivel, which is attached tohoisting equipment, carries much, if not all of, the weight of the drillstring 17, but may allow it to rotate freely.

The drill string 17 typically consists of sections of heavy steel pipe,which are threaded so that they can interlock together. Below the drillpipe are one or more drill collars, which are heavier, thicker, andstronger than the drill pipe. The threaded drill collars help to addweight to the drill string 17 above the drill bit to ensure that thereis enough downward pressure on the drill bit to allow the bit to drillthrough the one or more geological formations. The number and nature ofthe drill collars on any particular rotary rig may be altered dependingon the downhole conditions experienced while drilling.

The drill bit is typically located within or attached to the bottom holeassembly 45, which is located at a downhole end of the drill string 17.The drill bit is primarily responsible for making contact with thematerial (e.g., rock) within the one or more geological formations anddrilling through such material. According to the present disclosure, adrill bit type may be chosen depending on the type of geologicalformation encountered while drilling. For example, different geologicalformations encountered during drilling may require the use of differentdrill bits to achieve maximum drilling efficiency. Drill bits may bechanged because of such differences in the formations or because thedrill bits experience wear. Although such detail is not critical to thepresent disclosure, there are generally four types of drill bits, eachsuited for particular conditions. The four most common types of drillbits consist of: delayed or dragged bits, steel to rotary bits,polycrystalline diamond compact bits, and diamond bits. Regardless ofthe particular drill bits selected, continuous removal of the “cuttings”is essential to rotary drilling.

The circulating system of a rotary drilling operation, such as thedrilling assembly 15, may be an additional component of the drillingassembly 15. Generally, the circulating system has a number of mainobjectives, including cooling and lubricating the drill bit, removingthe cuttings from the drill bit and the wellbore, and coating the wallsof the wellbore with a mud type cake. The circulating system consists ofdrilling fluid, which is circulated down through the wellbore throughoutthe drilling process. Typically, the components of the circulatingsystem include drilling fluid pumps, compressors, related plumbingfixtures, and specialty injectors for the addition of additives to thedrilling fluid. In some embodiments, such as, for example, during ahorizontal or directional drilling process, downhole motors may be usedin conjunction with or in the bottom hole assembly 45. Such a downholemotor may be a mud motor with a turbine arrangement, or a progressivecavity arrangement, such as a Moineau motor. These motors receive thedrilling fluid through the drill string 17 and rotate to drive the drillbit or change directions in the drilling operation.

In many rotary drilling operations, the drilling fluid is pumped downthe drill string 17 and out through ports or jets in the drill bit. Thefluid then flows up toward the surface 12 within an annular space (i.e.,an annulus) between the wellbore portion 20 and the drill string 17,carrying cuttings in suspension to the surface. The drilling fluid, muchlike the drill bit, may be chosen depending on the type of geologicalconditions found under subterranean surface 12. For example, certaingeological conditions found and some subterranean formations may requirethat a liquid, such as water, be used as the drilling fluid. In suchsituations, in excess of 100,000 gallons of water may be required tocomplete a drilling operation. If water by itself is not suitable tocarry the drill cuttings out of the bore hole or is not of sufficientdensity to control the pressures in the well, clay additives (bentonite)or polymer-based additives, may be added to the water to form drillingfluid (i.e., drilling mud) As noted above, there may be concernsregarding the use of such additives in underground formations which maybe adjacent to or near subterranean formations holding fresh water.

In some embodiments, the drilling assembly 15 and the bottom holeassembly 45 may operate with air or foam as the drilling fluid. Forinstance, in an air rotary drilling process, compressed air lifts thecuttings generated by the drill bit vertically upward through theannulus to the terranean surface 12. Large compressors may provide airthat is then forced down the drill string 17 and eventually escapesthrough the small ports or jets in the drill bit. Cuttings removed tothe terranean surface 12 are then collected. Air drilling may includecertain advantages over drilling with a liquid as the drilling fluid.For instance, air drilling may allow for better hole cleaning as well asbetter indications of the downhole conditions in the wellbore portion20. Further, air drilling may allow for faster indication of water orhydrocarbons being produced into the wellbore portion 20. Additionally,air drilling often allows for lower pollution, faster penetration intothe one or more geological formations, and greater drill bit life. Airdrilling may also be advantageous, because air is readily available.

As noted above, the choice of drilling fluid may depend on the type ofgeological formations encountered during the drilling operations.Further, this decision may be impacted by the type of drilling, such asvertical drilling, horizontal drilling, or directional drilling. In somecases, for example, certain geological formations may be more amenableto air drilling when drilled vertically as compared to drilleddirectionally or horizontally. As one example of such considerations,certain areas of the United States include a hydrocarbon bearingformation called the Marcellus shale formation. The Marcellus shaleformation may typically require the use of a liquid, such as water, tobe used as the drilling fluid in drilling horizontally. Geologicalformations surrounding the Marcellus shale formation, however, may bemore amenable to the use of air when drilling horizontally. For example,in some areas, the Marcellus shale formation is located directlyadjacent to and under the Hamilton shale formation. The Hamilton shaleformation may be efficiently drilled using air as the drilling fluid.Further, the Hamilton shale formation is often located directly adjacentto and under a limestone formation called the Tully lime. The Tully limemay also be efficiently drilled on air. Further, highly organicformations such as the Marcellus shale formation, may be unsuitable forhorizontal drilling using compressed air circulation drilling processes.Competent shale formations, such as the Hamilton shale formation, may bedirectionally drilled on air with significantly greater efficiency andless use of resources such as water. Although one example group ofgeological strata has been described above, other groups exist and thepresent disclosure contemplates that one or more embodiments of thedeviated wellbore system 10 may be formed and utilized in any particulargeologic strata.

As illustrated in FIG. 1, the bottom hole assembly 45, including thedrill bit, drills or creates the vertical wellbore portion 20, whichextends from the terranean surface 12 towards the target subterraneanformation 50 and the productive formation 55. In some embodiments, thetarget subterranean formation 50 may be a geological formation amenableto air drilling. In addition, in some embodiments, the productiveformation 55 may be a geological formation that is less amenable to airdrilling processes. As illustrated in FIG. 1, the productive formation55 is directly adjacent to and under the target formation 50.Alternatively, in some embodiments, there may be one or moreintermediate subterranean formations (e.g., different rock or mineralformations) between the target subterranean formation 50 and theproductive formation 55.

In some embodiments of the deviated wellbore system 10, the verticalwellbore portion 20 may be cased with one or more casings. Asillustrated, the vertical wellbore portion 20 includes a conductorcasing 25, which extends from the terranean surface 12 shortly into theEarth. A portion of the vertical wellbore portion 20 enclosed by theconductor casing 25 may be a large diameter borehole. For instance, thisportion of the vertical wellbore portion 20 may be a 17-½“ borehole witha 13-⅜” conductor casing 25. Additionally, in some embodiments, thevertical wellbore portion 20 may be offset from vertical (e.g., a slantwellbore). Even further, in some embodiments, the vertical wellboreportion 20 may be a stepped wellbore, such that a portion is drilledvertically downward and then curved to a substantially horizontalwellbore portion. The substantially horizontal wellbore portion may thenbe turned downward to a second substantially vertical portion, which isthen turned to a second substantially horizontal wellbore portion.Additional substantially vertical and horizontal wellbore portions maybe added according to, for example, the type of terranean surface 12,the depth of one or more target subterranean formations, the depth ofone or more productive subterranean formations, and/or other criteria.

Downhole of the conductor casing 25 may be the surface casing 30. Thesurface casing 30 may enclose a slightly smaller borehole and protectthe vertical wellbore portion 20 from intrusion of, for example,freshwater aquifers located near the terranean surface 12. The verticalwellbore portion 20 may than extend vertically downward toward a kickoffpoint 47, which may be between 500 and 1,000 feet above the targetsubterranean formation 50. This portion of the vertical wellbore portion20 may be enclosed by the intermediate casing 35. In some embodiments,the borehole diameter of the vertical wellbore portion 20 in thisportion is approximately 6-¼″. Alternatively, the diameter of thevertical wellbore portion 20 at any point within its length, as well asthe casing size of any of the aforementioned casings, may be anappropriate size depending on the drilling process.

Upon reaching the kickoff point 47, drilling tools such as loggingequipment may be deployed into the wellbore portion 20. At that point, adetermination of the exact location of the bottom hole assembly 45 maybe made and transmitted to the terranean surface 12. Further, uponreaching the kickoff point 47, the bottom hole assembly 45 may bechanged or adjusted such that appropriate directional drilling tools maybe inserted into the vertical wellbore portion 20.

FIG. 2 illustrates another portion of one embodiment of a deviatedwellbore system 10 according to the present disclosure. For example,FIG. 2 illustrates the deviated wellbore system 10 after a curvedwellbore portion 60 and a horizontal wellbore portion 65 have beenformed within one or more geological formations. Typically, the curvedwellbore portion 60 may be drilled starting from the downhole end of thevertical wellbore portion 20 and deviated from the vertical wellboreportion 20 toward a predetermined azimuth gaining from between 9 and 18degrees of angle per 100 feet drilled. Alternatively, differentpredetermined azimuth may be used to drill the curved wellbore portion60. In drilling the curved wellbore portion 60, the bottom hole assembly45 often uses measurement-while-drilling (“MWD”) equipment to moreprecisely determine the location of the drill bit within the one or moregeological formations, such as the target subterranean formation 50.Generally, MWD equipment may be utilized to directionally steer thedrill bit as it forms the curved wellbore portion 60, as well as thehorizontal wellbore portion 65.

The horizontal wellbore portion 65 may typically extend for hundreds, ifnot thousands, of feet within the target subterranean formation 50.Although FIG. 2 illustrates the horizontal wellbore portion 65 asexactly perpendicular to the vertical wellbore portion 20, it isunderstood that directionally drilled wellbores, such as the horizontalwellbore portion 65, have some variation in their paths. Thus, thehorizontal wellbore portion 65 may include a “zigzag” path yet remain inthe target subterranean formation 50. Typically, the horizontal wellboreportion 65 is drilled to a predetermined end point 70, which, as notedabove, may be up to thousands of feet from the kickoff point 47. Asnoted above, in some embodiments, the curved wellbore portion 60 and thehorizontal wellbore portion 65 may be formed utilizing an air drillingprocess that uses air or foam as the drilling fluid.

FIG. 3 illustrates another portion of one embodiment of a deviatedwellbore system 10 including a deviated wellbore portion 75 according tothe present disclosure. For example, FIG. 3 illustrates the deviatedwellbore system 10 once the vertical wellbore portion 20, the curvedwellbore portion 60, and the horizontal wellbore portion 65 arecompletely formed in the one or more geological formations underneaththe terranean surface 12, such as the target subterranean formation 50.FIG. 3 also illustrates a deviated wellbore portion 75 formed bydrilling from the horizontal wellbore portion 65 into the productiveformation 55. Generally, the deviated wellbore portion 75 is a boreholeangularly directed downward from the horizontal wellbore portion 65 inthe target subterranean formation 50 into the productive formation 55.In some embodiments, the deviated wellbore portion 75 is also formedutilizing an air drilling process. Further, in some embodiments, thedeviated wellbore portion 75, once formed, may be used for a variety ofpurposes. For example, the deviated wellbore portion 75 may be used tointroduce fracturing fluid into the productive formation 55, thuscreating one or more fracs within the formation 55. In addition, thedeviated wellbore portion 75 may be used as a production wellbore, suchthat hydrocarbons (e.g., oil and gas) may be produced into the deviatedwellbore portion 75 and eventually to the terranean surface 12 throughthe horizontal wellbore portion 65, the curved wellbore portion 60, andthe vertical wellbore portion 20. Further, the deviated wellbore portion75 may be used in stimulation or secondary production processes. Forexample, an injection fluid, such as carbon dioxide or nitrogen, may beintroduced into the productive formation 55 through the deviatedwellbore portion 75 to help enhance production of hydrocarbons found inthe productive formation 55 to the terranean surface 12.

In some embodiments, the deviated wellbore portion 75 may be formedvertically offset from the horizontal wellbore portion 65. For example,the deviated wellbore portion 75 may be angularly displacedapproximately 90 degrees from the horizontal wellbore portion 65.Alternatively, the deviated wellbore portion 75 may be angularly elitedisplaced from the horizontal wellbore portion 65 less than 90 degrees(e.g., 75 degrees, 60 degrees, 30 degrees). In some embodiments, thedeviated wellbore portion 75 may be a 5- 3/4″ borehole. In manyinstances, the deviated wellbore portion 75 (as well as the curvedwellbore portion 60 and the horizontal wellbore portion 65) may beuncased boreholes or include a screen liner instead of traditionalcasing.

In some embodiments, the deviated wellbore portion 75 may be formedthrough a portion of the vertical thickness of the productive formation55. Alternatively, the deviated wellbore portion 75 may be drilledcompletely through the productive formation 55 and end in, for instance,a geological formation located adjacent to and under the productiveformation 55.

FIG. 4 illustrates another portion of one embodiment of a deviatedwellbore system 10 including a deviated wellbore group 80 a according tothe present disclosure. For example, in some embodiments of the deviatedwellbore system 10, multiple deviated wellbore portions 75 may be formedfrom the horizontal wellbore portion 65 and extending to the productiveformation 55. As illustrated in FIG. 4, the deviated wellbore group 80 amay consist of five deviated wellbore portions 75; fewer or greaternumber of deviated wellbore portions 75 may make up a deviated wellboregroup as appropriate. In some embodiments, each deviated wellboreportion 75 drilled within the deviated wellbore group 80 a may besubstantially identical. For instance, each deviated wellbore portion 75within the group 80 a may be angularly displaced from the horizontalwellbore portion 65 at substantially the same angle (A) (e.g., 85degrees). Further, each deviated wellbore portion 75 may beapproximately the same length (L), or in other words, extend into theproductive formation 55 the same or substantially the same distance. Inaddition, each deviated wellbore portion 75 may be laterally spaced adistance (D) from adjacent deviated wellbores along the horizontalwellbore portion 65, where D is substantially equal between successivedeviated wellbore portions 75 within the group 80 a.

Alternatively, the aforementioned characteristics of the individualdeviated wellbore portions 75 within the deviated wellbore group 80 amay be distinct from wellbore portion 75 to wellbore portion 75. Forinstance, the angular displacement (A) of each deviated wellbore portion75 within the group 80 a may be distinct. The length (L) of eachdeviated wellbore portion 75 within the group 80 a may be distinct. Insome embodiments, for example, MWD and logging-while drilling (LWD)technology may be utilized to determine a lower boundary or edge of theproductive formation 55. As geological formations such as the productiveformation 55 may be undulating and varying in thickness, a true verticaldepth (TVD) of such a lower edge may vary along the formation 55. Eachdeviated wellbore portion 75 may be drilled to approach such a loweredge, thus making the lengths (L) of each deviated wellbore portion 75vary within the group 80 a. As another example, the spacing (D) betweenadjacent deviated wellbores portions 75 within the deviated wellboregroup 80 a may vary.

Each of these variable and adjustable characteristics may bepredetermined prior to drilling the deviated wellbore system 10 ordetermined during the drilling of the deviated wellbore system 10. Forinstance, such characteristics (A, L, D), as well as others, may bepredetermined according to a planned fracture or stimulation treatment(e.g., type of fracture or injection fluid used in such processes).Alternatively, or in addition, one or more of such characteristics (A,L, D) may be determined during the drilling process according to, forexample, the geological characteristics of the target subterraneanformation 50, the productive formation 55, or other geologic formationsadjacent or near such formations.

FIGS. 5A-B illustrate different views of one embodiment of a deviatedwellbore system 10 including multiple deviated wellbore groups 80 a-daccording to the present disclosure. With reference to FIG. 5Aspecifically, a side view of one embodiment of the deviated wellboresystem 10 is illustrated. As illustrated, the deviated wellbore system10 includes deviated wellbore groups 80 a-d. Each deviated wellboregroup 80 a-d includes five deviated wellbore portions 75 and each group80 a-d is laterally offset (O) from adjacent wellbore groups. As withthe characteristics A, L, and D above, the offset (O) may bepredetermined according to, for instance, a planned fracture treatment(e.g., type of fracture fluid) or stimulation treatment (e.g.,acidizing), or even one or more of the other deviated wellborecharacteristics, A, L, or D. Alternatively, or in addition, the offset(O) may be determined during the drilling process according to, forexample, the geological characteristics of the target subterraneanformation 50, the productive formation 55, or other geologic formationsadjacent or near such formations. Alternatively, other drilling data,processes, equipment, or experience may determine one or more of thecharacteristics (A, L, D, O). Of course, the deviated wellbore system 10may include fewer or greater number of deviated wellbore groups 80 a-dand fewer or greater deviated wellbore portions 75 within each group. Inaddition, one or more characteristics (A, L, D) of each deviatedwellbore portion 75 may vary from group to group.

Turning now to FIG. 5B, a sectional view of the horizontal wellboreportion 65 and deviated wellbore groups 80 a-c along the horizontalwellbore portion 65 is illustrated. As illustrated, the deviatedwellbore groups 80 c-d are radially offset from a downward verticaldirection. For example, the deviated wellbore group 80 c is offset atone angle (R2) from the vertical down direction. The deviated wellboregroup 80 d is offset at another angle (R1) from the vertical downdirection. As illustrated, the deviated wellbore group 80 b is notradially offset from vertical down. In short, each deviated wellboregroup 80 a-d may be radially offset about the horizontal wellboreportion 65 at similar or distinct values. For instance, in someembodiments, R1 may be equal to approximately 10 degrees from verticaldown while R2 may be 15 degrees from vertical down. Such angles R1 andR2 may be any appropriate value depending on, for instance, othercharacteristics of the deviated wellbores 75, the deviated wellboresystem 10, or one or more drilling or completion operations (e.g.,fracing, stimulation, production).

FIG. 6 illustrates one embodiment of a deviated wellbore system 10including multiple deviated wellbore groups 80 a-d during a fracing,stimulation, or production operation according to the presentdisclosure. As illustrated in FIG. 6, one or more packers 85 and sleeves90 may be inserted into the horizontal wellbore portion 65 via thevertical wellbore portion 20. As used herein, the terms “packer” and“sleeve” mean any generic or application specific packer and sleeve,respectively. In other words, the packer 85 may generally be anydrilling process device that can be inserted into a wellbore that mayhave a smaller initial outside diameter and may then expand externallyto seal the wellbore and/or any completion process device that mayisolate an annulus from a production conduit, thus enabling controlledproduction, injection or treatment. The sleeve 90 may generally be anydevice that may provide a flow path between a production conduit and anannulus, such as a sliding sleeve that incorporates a system of portsthat can be opened or closed by a sliding component.

As illustrated, the packers 85 may be arranged between each deviatedwellbore group 80 a-d such that one or more of the groups 80 a-d may beisolated from one or more other groups 80 a-d. Thus, hydrocarbonproduction, fracture generation, or stimulation operations may becompleted on each deviated wellbore group or multiple deviated wellboregroups, as appropriate. Further, each sleeve 90 may be positioned at anintersection of a particular deviated wellbore group 80 a-d and thehorizontal wellbore portion 65, thus allowing controlled production,fracing, and/or stimulation from each deviated wellbore group 80 a-d.FIG. 6, therefore, illustrates some example arrangements and operationsof the packers 85 and the sleeves 90. But many other operations and/ordownhole tools may be used in conjunction with the deviated wellboresystem 10, the deviated wellbore groups 80 a-d, and the deviatedwellbores 75, as appropriate.

FIG. 7 illustrates a plan view of one embodiment of a system 700including multiple deviated wellbore systems 710 a-b according to thepresent disclosure. Generally, FIG. 7 illustrates multiple deviatedwellbore systems 710 a-b that share a common vertical wellbore portion720. Thus, the multiple systems 710 a-b (as well as future deviatedwellbore systems 710 c-d) may be drilled from a single vertical wellboreportion 720, thus minimizing the number of surface disturbances anddrilling operations. As illustrated, the deviated wellbore system 710 aincludes the vertical wellbore portion 720, a curved wellbore portion760 a, a horizontal wellbore portion 765 a, and multiple deviatedwellbore portions 775 within multiple deviated wellbore groups 780 a 1through 780 a 3. The deviated wellbore system 710 a, the deviatedwellbore groups 780 a 1 through 780 a 3 and the deviated wellboreportions 775 may be identical or substantially identical to suchcomponents as described above with reference to FIGS. 1-6. Further, asillustrated, the deviated wellbore system 710 b includes the verticalwellbore portion 720, a curved wellbore portion 760 b, a horizontalwellbore portion 765 b, and multiple deviated wellbore portions 775within multiple deviated wellbore groups 780 b 1 through 780 b 4. As maybe recognized, future deviated wellbore systems, such as systems 710c-d, may also share the vertical wellbore portion 720. In addition,fewer or greater systems 710 may share the vertical wellbore portion 720as are shown in FIG. 7. Further, as illustrated, the deviated wellboresystem 710 a and the deviated wellbore system 710 b are approximately180 degrees apart with respect to the vertical wellbore portion 720.Alternatively, the systems 710 a and 710 b, or any number of deviatedwellbore systems, may be less than 180 degrees apart with respect to thevertical wellbore portion 720 (e.g., 15 degrees, 20 degrees, etc.).

A number of embodiments have been described. Nevertheless, it will beunderstood that various modifications may be made. For instance FIGS.1-6 illustrate one embodiment of a deviated wellbore system in which ahorizontal wellbore is drilled within a target subterranean formationadjacent and above a productive formation. In some embodiments, thehorizontal wellbore may be drilled into a target subterranean formationlocated adjacent and below a productive formation. Thus, deviatedwellbores formed from the horizontal wellbore and extending into theproductive formation may be angularly displaced vertically upward fromthe horizontal wellbore. Such embodiments may be implemented, forinstance, when the productive formation contains heavy oil or otherviscous hydrocarbon. After completion of such a deviated wellboresystem, such heavy oil may be produced by, for example, injecting steamor other high-temperature fluid into the productive formation from thedeviated wellbores, such as, for example, in steam assisted gravitydrainage (SAGD) operations. Accordingly, other embodiments are withinthe scope of the following claims.

1. A method comprising: forming a first wellbore portion from aterranean surface to a predetermined depth in or near a first targetsubterranean formation, the first wellbore portion having an uppersection extending from the terranean surface downward in a substantiallyvertical manner for at least a portion of the depth to the firsttargeted subterranean formation; forming a second wellbore portioncoupled to the first wellbore portion, the second wellbore portionformed substantially horizontal to and in substantial entirety withinthe first target subterranean formation; and forming a plurality ofthird wellbore portions comprising a plurality of deviated wellboresextending angularly downward into a lower second target subterraneanformation from the second wellbore portion, the second targetsubterranean formation including at least one of oil or gas.
 2. Themethod of claim 1, wherein the first wellbore portion comprises aslanted wellbore from the terranean surface to the predetermined depth.3. The method of claim 1, wherein forming the upper vertical section ofthe first wellbore portion comprises drilling through one or more ageologic formations utilizing air as a drilling fluid.
 4. The method ofclaim 1, wherein forming the second wellbore portion comprises drillingthrough the first target subterranean formation utilizing air as adrilling fluid.
 5. The method of claim 1, wherein forming the pluralityof third wellbore portions comprises drilling through the second targetsubterranean formation utilizing air as a drilling fluid.
 6. The methodof claim 1, wherein forming the upper vertical section of the firstwellbore portion comprises drilling through one or more a geologicformations utilizing foam as a drilling fluid.
 7. The method of claim 1,wherein forming the second wellbore portion comprises drilling throughthe first target subterranean formation utilizing foam as a drillingfluid.
 8. The method of claim 1, wherein forming the plurality of thirdwellbore portions comprises drilling through the second targetsubterranean formation utilizing foam as a drilling fluid.
 9. The methodof claim 1, wherein the first target subterranean formation is directlyadjacent the second target subterranean formation and between theterranean surface and the second target subterranean formation.
 10. Themethod of claim 1, wherein the plurality of deviated wellbores areformed from the second wellbore portion at a downward angle less than 90degrees from horizontal.
 11. The method of claim 1, wherein forming aplurality of third wellbore portions comprising a plurality of deviatedwellbores extending angularly into a second target subterraneanformation from the second wellbore portion comprises forming a pluralityof deviated wellbores extending angularly into the second targetsubterranean formation from the second wellbore portion and completelythrough the second target subterranean formation.
 12. The method ofclaim 1, wherein forming a plurality of third wellbore portionscomprising a plurality of deviated wellbores extending angularly into asecond target subterranean formation from the second wellbore portioncomprises: forming a first group of deviated wellbores extendingangularly into the second target subterranean formation; and forming asecond group of deviated wellbores extending angularly into the secondtarget subterranean formation, the second group of deviated wellboresseparated from the first group of deviated wellbores by a lateraloffset.
 13. The method of claim 12 further comprising determining thelateral offset between the first and second groups of deviated wellboresbased at least in part on a predetermined fracture process or apredetermined stimulation process for the second target subterraneanformation.
 14. The method of claim 12, wherein forming a first group ofdeviated wellbores extending angularly into the second targetsubterranean formation comprises forming a first group of deviatedwellbores extending angularly into the second target subterraneanformation at a first angle from horizontal; and forming a second groupof deviated wellbores extending angularly into the second targetsubterranean formation comprises forming a second group of deviatedwellbores extending angularly into the second target subterraneanformation at a second angle distinct from the first angle.
 15. Themethod of claim 14 further comprising determining the first and secondangles based at least in part on a predetermined fracture process or apredetermined stimulation process for the second target subterraneanformation.
 16. The method of claim 1, the plurality of deviatedwellbores comprising a first plurality of deviated wellbores, the methodfurther comprising: forming a fourth wellbore portion coupled to thefirst wellbore portion, the fourth wellbore portion radially offset fromthe second wellbore portion and formed substantially horizontal to andin substantial entirety within the first target subterranean formation;and forming a second plurality of deviated wellbores extending angularlyinto the second target subterranean formation from the fourth wellboreportion.
 17. The method of claim 1, wherein the second targetsubterranean formation comprises a hydrocarbon bearing shale formation.18. The method of claim 1, wherein at least one of the first wellboreportion, the second wellbore portion, and the plurality of deviatedwellbores are formed by rotary drilling equipment.
 19. The method ofclaim 1, wherein forming a plurality of deviated wellbores extendingangularly into a second target subterranean formation from the secondwellbore portion comprises forming a plurality of deviated wellboresextending downwardly into a second target subterranean formation fromthe second wellbore portion and angularly offset from horizontal andvertical.
 20. A system comprising: a primary wellbore comprising: asubstantially vertical portion extending from a terranean surface to apredetermined location above a first target subterranean formation; acurved portion coupled to the substantially vertical portion andextending through the first target subterranean formation above a secondtarget subterranean formation containing at least one of oil or gas; anda substantially horizontal portion coupled to the curved portion andextending through the first target subterranean formation and adjacentthe second target subterranean formation; and a plurality of secondarywellbores coupled to the primary wellbore and extending angularlydownward into the second target subterranean formation.
 21. The systemof claim 20, wherein the substantially vertical portion of the primarywellbore is formed by drilling through one or more a geologic formationsutilizing air as a drilling fluid.
 22. The system of claim 20, whereinthe substantially horizontal portion of the primary wellbore is formedby drilling through one or more a geologic formations utilizing air as adrilling fluid.
 23. The system of claim 20, wherein at least one of theplurality of secondary wellbores is formed by drilling through one ormore a geologic formations utilizing air as a drilling fluid.
 24. Thesystem of claim 20, wherein the substantially vertical portion of theprimary wellbore is formed by drilling through one or more a geologicformations utilizing foam as a drilling fluid.
 25. The system of claim20, wherein the substantially horizontal portion of the primary wellboreis formed by drilling through one or more a geologic formationsutilizing foam as a drilling fluid.
 26. The system of claim 20, whereinat least one of the plurality of secondary wellbores is formed bydrilling through one or more a geologic formations utilizing foam as adrilling fluid.
 27. The system of claim 20, wherein the first targetsubterranean formation is directly adjacent the second targetsubterranean formation and between the terranean surface and the secondtarget subterranean formation.
 28. The system of claim 20, wherein theplurality of secondary wellbores are coupled to the substantiallyhorizontal portion of the primary wellbore.
 29. The system of claim 28,wherein the plurality of secondary wellbores are formed from thesubstantially horizontal portion at a downward angle less than 90degrees from horizontal.
 30. The system of claim 20, wherein at leastone of the plurality of secondary wellbores extends completely throughthe second target subterranean formation.
 31. The system of claim 20,wherein the plurality of secondary wellbores comprise: a first group ofsecondary wellbores extending angularly downward into the second targetsubterranean formation; and a second group of secondary wellboresextending angularly downward into the second target subterraneanformation, the second group of secondary wellbores separated from thefirst group of secondary wellbores within the second target subterraneanformation by a lateral offset.
 32. The system of claim 31, wherein thelateral offset between the first and second groups of secondarywellbores is based at least in part on a predetermined fracture processor a predetermined stimulation process of the second target subterraneanformation.
 33. The system of claim 31, wherein the first group ofsecondary wellbores extend angularly downward into the second targetsubterranean formation at a first angle from horizontal and the secondgroup of secondary wellbores extend angularly downward into the secondtarget subterranean formation at a second angle from horizontal, thesecond angle distinct from the first angle.
 34. The system of claim 33,wherein the first and second angles are determined based at least inpart on a predetermined fracture process or a predetermined stimulationprocess of the second target subterranean formation.
 35. The system ofclaim 20, the curved portion comprising a first curved portion, thesystem further comprising: a second curved portion coupled to thesubstantially vertical portion and radially offset from the first curvedportion around the substantially vertical portion, the second curvedportion extending through the first target subterranean formation abovethe second target subterranean formation; a second substantiallyhorizontal portion coupled to the second curved portion and extendingthrough the first target subterranean formation and adjacent the secondtarget subterranean formation; and a second plurality of secondarywellbores extending angularly downward into the second targetsubterranean formation from the second substantially horizontal portion.36. The system of claim 20, wherein the second target subterraneanformation comprises a hydrocarbon bearing shale formation.
 37. Thesystem of claim 20, wherein at least one of the primary wellbore and theplurality of secondary wellbores are formed by rotary drillingequipment.